This invention relates to a fossil-fired power or steam generation thermal system, and, more particularly, to a method for determining its fuel chemistry, fuel heating value, fuel flow, and thermal performance from its basic operating parameters.
The importance of accurately determining thermal efficiency is critical to any thermal system. If practical day-to-day improvements in efficiency are to be made, and/or problems in thermally degraded equipment are to be found and corrected, then accuracy in determining thermal efficiency is a necessity. The tracking of the efficiency of any thermal system lies fundamentally in measuring the useful output, and the total in-flow of fuel. The useful output from a fossil fueled system includes the generation of electrical and/or mechanical power and/or the production of a heated working fluid such as steam.
The measuring of the useful output of thermal systems is highly developed and involves the direct measurement of electrical output and/or mechanical drives and/or thermal energy flow. Measuring electrical and mechanical power is well established. Measuring thermal energy flow involves direct measurement of the inlet and outlet pressure, temperature and/or quality of a fluid being heated by the combustion gases, as well as measurement of its mass flow rate (m). From this information enthalpies (h) may be determined, and thus the total energy flow, m(houtletxe2x88x92hinlet), delivered from the combustion gases, when also considering incidental losses, may be determined.
The measurement of the energy flow of the input fuel requires knowledge of the heating value of the fuel and its mass flow rate. For thermal systems using gaseous fuels, the fuel""s composition may be well characterized, thus its heating value may be determined based on known heats of combustion associated with individual components.
However, there are numerous situations where a fossil-fueled system""s fuel energy flow is not well characterized. For example, even a gas-fired system, having no on-site fuel gas analyzer, may receive fuel from multiple sources whose composite heating value variation is xc2x15 percent or greater. The measurement of fuel flow may often present a problem of measurement accuracy, especially at lower loads where flow measurement devices are not calibrated. In either case the determination of fuel energy flow is critical for proper thermal understanding of any fossil-fired system, either for direct confirmation of computed results and/or for improving system thermal efficiency.
The importance of accurately determining pollutant concentrations and their flow rates is also critical to the practical operation of any fossil-fired system due to environmental constraints imposed through regulation, the potential of regulatory induced fines, and concern by the owner of the facility for environmental protection.
Given these considerations, it is equally important to have analytical evidence of the errors made in the determination of fuel flow and the errors in fuel heating value, and thus the resultant errors in the determined thermal efficiency of the system. Further, any error in effluent flow, which is proportional to any error made in fuel flow, is significant when monitoring and reporting to regulatory agencies the effluents from any source of fossil combustion. The method of this invention provides a technique for specifying and correcting possible errors based on the consistency of the primary measurements of effluent O2, CO2, indicated Air/Fuel ratio, assumed or measured effluent H2O, possible air pre-heater leakage and the concentration of O2 in combustion air.
The measurement of fuel flow has traditionally been accomplished via measurement of its mechanical effects on a device. Such effects include the pressure drop across nozzles or orifice plates, unique fluid densities, integrated weighing of a fuel handling conveyor belt (commonly used for bulk fuels such as coal), speed of sound, nuclear resonance, change in bulk storage levels, etc. Present industrial techniques for measuring gas or oil fuel flow result in typical errors of 1 percent to 10 percent relative to true values, depending on the care taken in designing, manufacturing, installing and calibrating the flow metering equipment and in its data reduction. Under ideal circumstances, tighter accuracies (i.e., smaller errors) are possible for gas and oil fuels, reaching at best 0.25 percent, but this is considered very unusual, always requiring extraordinary expense.
For bulk fuel such as coal, bio-mass, slurry fuels, wood, agricultural byproducts such as shells from nuts, trash and refuse, the typical accuracies of flow metering range upwardly from 5 percent and higher. Historically, bulk flow measurements have such poor accuracy that they are used only as a relative indicator of fuel flow. For fossil-fired systems any fuel flow error greater than approximately 1 percent, and certainly greater than 2 percent, is sufficiently high to preclude trending of the monitored fuel flow rate for reasons of thermal efficiency or for detecting degraded equipment. Improvement of efficiencies in a thermal system is classically concerned with a number of small incremental improvements, typically each in the range of 0.2 percent to 0.6 percent. A dozen or more of these, taken together, may result in 3 percent to 6 percent improvement. For example, an average 4.5 percent improvement has been physically demonstrated at over two dozen conventional power plants, see F. D. Lang, xe2x80x9cMethodology for Testing and Evaluating Power Plants Using Computer Simulatorsxe2x80x9d, 1990 Performance Software User""s Group Meeting, May 1-4, 1990, St. Louis, sponsored by EI International, now Scientech Inc. of Idaho Falls, Id. Prior approaches which attempt to address the accurate determination of fuel flow are discussed below.
Another critical consideration in determining thermal efficiency is the variation in the fuel""s heating value due to variations in fuel chemistry. Chemical variations appear through the mix of fuel water, fuel mineral matter (called fuel ash), and the relationships of the elements comprising the basic hydrocarbon molecular chain and any free inorganic elements: nitrogen, oxygen, carbon, hydrogen and sulfur; but principally carbon, hydrogen and oxygen. If an accurate and direct flow measurement of bulk fuels is not practical, the only alternative is the determination of fuel energy flow, which is the product of flow rate and heating value of the fuel, based in part on the measured energy flow to the working fluid. If errors exist in the heating value, either an assumed, measured, or calculated value, errors will then result in the fuel flow. Prior approaches which attempt to address the determination of fuel energy flow are discussed below. Further, over the past 140 years of producing safe high pressure steam for society, mostly from coal, there has been no invention or process even suggesting an ability to determine a coal""s fuel ash content in real time based on thermodynamics.
The approach of this invention is a much improved xe2x80x9cInput/Loss Methodxe2x80x9d. Prior input/loss methods have been known to the inventor, and to T. Buna as early as 1955.
One prior approach related to the present invention was developed by T. Buna in 1955 for the analysis of multiple fuels fed to a power plant. His approach was to characterize a fuel""s effluent CO2, given differing effluent O2 values, by assuming fuel chemistry of the individual fuels. With this data for multiple fuels and knowledge of the Useful Energy Flow Delivered, he advocated determining each fuel""s flow rate. He presents an xe2x80x9coutput-lossxe2x80x9d and an xe2x80x9cinput-lossxe2x80x9d approaches to determining boiler efficiency. The present invention is related only in that a course reversed from Buna""s method is accomplished. This invention computes fuel chemistry based on effluent measurements, it assumes that all secondary fuels, unlike Buna, are known having defined chemistries, heating values and As-Fired flows. The reference is: T. Buna, xe2x80x9cCombustion Calculations for Multiple Fuelsxe2x80x9d. ASME Diamond Jubilee Annual Meeting, Chicago, Ill., Nov. 13-18, 1955, Paper 55-A-185.
Another related art to the present invention was developed by the Electric Power Research Institute (EPRI) at the Morgantown power plant, a coal-fired conventional system. This technique, termed the xe2x80x9cOutput/Lossxe2x80x9d Method, is described by E. Levy, N. Sarunac, H. G. Grim, R. Leyse and J. Lamont, xe2x80x9cOutput/Loss: A New Method for Measuring Unit Heat Ratexe2x80x9d, Am. Society of Mech. Engrs., 87-JPGC-Pwr-39. The Output/Loss Method produces boiler efficiency (xcex7boiler) independent of fuel flow. Assuming a conventional power plant, by determining the energy flow to the working fluid (xcexa3mxcex94h) and gross electrical power production (P), system thermal efficiency may be determined, i.e., (xcex7boiler)(xcexa3mxcex94h). In addition, although it is not the objective of the Output/Loss Method, if heating value and boiler energy credits (HHVP+HBC) are known, then the As-Fired fuel flow (mAF) may be determined as mAF=(xcexa3mxcex94h)/[xcex7boiler(HHVP+HBC)]. Use of boiler energy credits (HBC), and gross power (P) versus net power, are discussed in the Preferred Embodiment. The technique relies on measuring emission gas flow directly, and thus xcex7boiler. Knowing emission gas flow allows the determination of the majority of the thermal losses associated with combustion, called xe2x80x9cStack Lossesxe2x80x9d. However, this approach has drawbacks when it is applied for practical applications in power plants for the following reasons: 1) it does not rely on measurement of flue gas concentrations (thus changes in the in-flows of water/steam to the combustion process, or changes in effluent CO2, as might reflect changes in fuel chemistry or air pre-heater leakages); 2) the errors in effluent gas flow measurements in irregular ducts not designed for accurate flow measurements, which is the case at most power plant facilities, may easily exceed xc2x120 percent, resulting in over xc2x14 percent error in system efficiency since typically stack losses are ≈20 percent (i.e., xc2x14 percent error in fuel flow); 3) the technique of direct flue gas flow measurements does not consistently meet current U.S. Environmental Protection Agency""s accuracy requirements of xc2x115 percent; 4) it is obvious from the above discussion that if the fuel""s heating value (HHV) is variable, as is common with most coal-fired systems, and is not properly monitored in a continuous manner, then calculated fuel flow will also be in error, due to errors made in the assumed heating value; 5) direct measurement of effluent flow commonly involves ultrasonic, sonic or direct gas velocity measurements, requiring assumptions as to effluent compositions, i.e., fuel constituents and air pre-heater leakage, errors in these will force errors in the deduced effluent flow; and 6) if the fuel bears highly variable quantities of ash (a pure dilutive or concentrative influence on fuel heating value, but affects effluent flows through Air/Fuel relationships), then the computed fuel flow, since it is dependent on an assumed heating value with an assumed ash content, will likely be in error.
Another related art to the present invention was presented at a technical conference in 1988 by S. S. Munukutla, et al. In this work the authors develop a process which used effluent measurements to determine the Moisture-As-Free (MAF) composition of coal. Their published work teaches little relative to the art of monitoring thermal performance and the determination of coal chemistry of practical operating power plants. Munukutla, et al., do not consider air pre-heater leakage, but measure combustion effluents before the air pre-heater (at the economizer outlet). They invoke high accuracy effluent measurements afforded with gas chromatography, not common industrial instruments. This basic technique, commonly referred to as Thermal Analysis using in part gas chromatography, is used in laboratories to determine heating values under highly controlled conditions, refer to Chapter 9, xe2x80x9cMeasurement of Heat of Combustionxe2x80x9d contained in Steam, Its Generation and Use, 40th Edition, edited by S. C. Stultz and J. B. Kitto, published 1992 by the Babcock and Wilcox Company, Barberton, Ohio. It was also the subject of inventor""s earlier U.S. Pat. No. 5,327,356. They do not consider the injection of limestone as is common with fluidized bed combustors, representing the largest single type of steam generator sold outside the U.S. They make no claims for the on-line determination of fuel ash, but assume it is constant based on laboratory analysis. Errors are made in their Equation 3, which if applied to their process would yield ridiculous results. This error is corrected in subsequent works by Munukutla as presented in 1989 and later. The ratio of atmospheric non-O2 (principally N2 and Ar) to O2 is set as a constant in their work at 3.76 (which assumes O2 at 21.0 percent). First, this ratio, commonly found in fundamental thermodynamic text books, is in error; the correct ratio is 3.7737, herein termed xcfx86Act , derived from a value of 20.948 percent atmospheric O2 per NASA (reference U.S. Standard Atmosphere 1976, NOAA-S/T-76-1562-NASA). Not using a correct value results in an error in determining excess air and molar oxygen balances. Second, in approximately 10% of the power plants tested by the inventor, atmospheric O2 may be degraded, resulting in a higher xcfx86Act value, due to in-leakage of flue gases into the combustion air stream and/or local atmospheric inversions which may result in starving the local environment for oxygen. In the present invention this ratio is expressed as a variable, xcfx86Act, to be set by the user based on circumstances local to the thermal system.
At a systems understanding level, the 1988 approach by Munukutla, et al., is lacking for they compute boiler efficiency only as a final result of the technique using the Input-Output Method (discussed below); see their Equation 10. A computed boiler efficiency incorporated within the technique proper is lacking, thus integral consistency required for, and a feature of, the present invention is not assured using their methods. A most important attribute of the present invention demonstrates an integral relationship between coal constituents and the determination of boiler efficiency, leading to system efficiency; indeed without coal constituents boiler efficiency simply cannot be computed by the present invention. Munukutla, et al., technique determines the total fuel energy flow from system energy flow balances (their FIG. 2 and Equation 4), developing a xe2x80x9cfuel energyxe2x80x9d term, AmMAF=Qrad+Qsteam; offering no explanation as to how the term xe2x80x9cAxe2x80x9d in this expression is related to coal heating value, as one might assume. However, this expression is then used to develop mass flow rates of the coal""s constituents, termed xcexc1, (in pounds/second). These xcexc1 terms are then used in a correlation which develops total fuel energy flow (Btu/hr), thus bypassing a boiler efficiency calculation. Air pre-heater leakage is not considered in their system energy balances. It is noteworthy that this energy balance technique, leading to their Equation 4, is not referenced in later publications on the same subject by the same principal author (in 1989, 1991 and 1995), however the basic stoichiometrics, corrected, are referenced. The reference for this work is S. S. Munukutla, G. Tsatsaronis, Y. Shih, D. E. Anderson and S. M. Wilson, xe2x80x9cA Microcomputer Software for On-Line Evaluation of Heat Ratexe2x80x9d, ASME Power Generation Conference, Philadelphia, Pa., Sep. 25-29, 1988, Paper 88-JPGC/PTC-1.
In three later works, Munukutla and his colleagues attempt to refine the technique. At a 1989 conference, published in 1990, Munukutla and A. Bose again propose using gas chromatography to measure economizer outlet gaseous effluents in determining MAF heating values. The heating value correlation employed, using weight fractions of coal""s constituents, was the Mott-Spooner correlation based on Dulong""s formula. These are both well known correlations in the industry, however they are not based on chemical binding energies as this invention employs. However in this 1989 work, the correlation was used incorrectly; the correlation was intended for MAF fuel constituents, Munukutla and Bose inconsistently used the wet As-Fired. As witness to the inaccuracy of their work, their calculated MAF heating value reasonably agreed with the As-Fired (wet). In 1991. Munukutla, P. Chodavarapu and D. C. O""Connor published essentially the same work as in 1989, again based on gas chromatography effluent measurements. In their 1991 work fuel water is either measured or determined by difference, assuming the remaining effluents are measured on a wet base. It is obvious from their work that reasonably accurate molecular weights are not used; given the sensitivity of any such approach, such errors amount to ≈1% error (using their numerical examples, the fuel carbon fraction is computed as 0.6616, versus the correct 0.6570 as determined by simply using correct molecular weights. Further, as with the 1988 and 1989 work, no provisions are made for limestone injection. Again the 1991 work used the Mott-Spooner correlation based on Dulong""s formula to determine the heating value, HHVMAF, but this time the authors used the consistent MAF fuel constituents, later correcting HHVMAF for fuel water and ash. The result was in error with the reported value by 387 xcex94Btu/lbm, or 3.1%. Using only their 1991 reported fuel analysis, this invention""s methods produced an error of 162 xcex94Btu/lbm. They also reported results of 14 tests preformed, resulting in a standard deviation of xc2x1785 xcex94Btu/lbm, or xc2x15.6%. In 1995, Munukutla and F. Khodabakhsh published a similar work as in 1989 and 1991, but this time based effluent measurements on continuous emission monitoring system (CEMS) instrumentation. CEMS instrumentation is required by the US EPA on all stationary sources of pollutants. Effluent measurements include CO2, CO, O2, SO2 and volumetric flow rate. Under US and European regulations these measurements must be made at the boundary of the system, at the air pre-heater""s outlet, i.e., the smoke stack, not at the boiler""s outlet (i.e., the air pre-heater inlet); refer to FIG. 6. Munukutla and Khodabakhsh applied the same stoichiometrics for this work was used since 1988, applicable for a system without air pre-heater leakage. Given the measurements are made with air leakage present, the method is fundamentally flawed; all effluents emanating from the combustion process are of course diluted with air leakage. However, the system was defined in such a manner that air leakage was factored out when considering a system energy balances. This was done by using the air pre-heater""s hot outlet flow to the boiler, per their FIG. 2, not the combustion air inlet to the air pre-heater. The consequence of this is that although fuel flow could be computed correctly, the integral determination of boiler efficiency, as with the 1988 work, is not possible. Further, since the proposed effluent measurements in this 1995 work are inconsistent with its basic analytics, the computed fuel constituents are then seriously flawed. Limestone injection is not considered. Fuel ash is assumed constant. In all of these works, from 1988 through 1995, no mention is made of converting the resultant heating value from a constant volume base to a constant pressure base as required given that laboratory determined coal heating values derive from xe2x80x9cbomb calorimeterxe2x80x9d devices, a constant volume process. However, a refinement described in their 1995 work suggests an iterative correction of the measured CEMS volumetric flow with that computed through stoichiometrics. The present invention does not employ effluent flow measurements and thus this refinement is not material.
References for the 1989, 1991 and 1995 works by Munukutla and his colleagues include: S. Munukutla and A. Bose, xe2x80x9cOn-Line Elemental Analysis of Coal Using Gas Chromatographyxe2x80x9d, 1989 EPRI Heat Rate Improvement Conference, May 3-5, Knoxville, Tenn., published 1990); S. Munukutla, P. Chodavarapu and D. C. O""Connor, xe2x80x9cOn-Line Coal Analysis from Measurement of Flue Gas Componentsxe2x80x9d. ASME International Power Generation Conference, San Diego, Calif., Oct. 6-10, 1991, Paper 91 -JPGC-Pwr-17; and S. Munukutla and F. Khodabakhsh, xe2x80x9cEnhancement of Boiler Performance Evaluation Methods Using CEMS Dataxe2x80x9d, ASME International Joint Power Generation Conference, Minneapolis, Minn., Oct. 8-12, 1995, PWR-Volume 29, 1995.
Another approach was developed by the present inventor and was described in U.S. Pat. No. 5,367,470. The invention of the ""470 patent is noteworthy because it addresses the determination of boiler efficiency without knowledge of fuel flow and without knowledge of effluent flow, but knowing principally effluent CO2, effluent H2O and routine system data, and it is useful in many situations. However, the Air/Fuel ratio is not required in the method of the ""470 patent. A key to the invention of the ""470 patent is its requirement to repetitiously adjust, or iterate, on xe2x80x9can assumed water concentration in the fuel until consistency is obtained between the measured CO2 and H2O effluents and those determined by stoichiometrics based on the chemical concentration of the fuelxe2x80x9d. Some aspects of the invention are dependent upon high accuracy effluent water and carbon dioxide concentration measurements, or xe2x80x9cpredetermined accuraciesxe2x80x9d of these effluents. The present invention has no such limitations on accuracy. The difficulty in the method of the ""470 patent lies with the fact that adjusting fuel water, which will of course alter the computed effluent water, has no prima facie effect on a dry-base effluent CO2. It is true, for example, that if fuel water is increased, the relative fraction of the other fuel""s constituents, per unity mole of total As-Fired fuel, will decrease assuming that the fuel""s other constituents, nitrogen, oxygen, carbon, hydrogen, sulfur and ash, remain proportionally constant to each other. However, it would be unusual that any given fuel water adjustment would produce an exactly consistent effluent CO2, with the exception where the dry chemistry is constant or highly predictable. Further, if the fuel has a variable ash content, ash having a pure dilutive or concentrative influence on fuel chemistry and fuel heating value, then such variable effect could not possibly be determined by merely iterating on fuel water. A higher assumed fuel water may decrease a wet-base effluent CO2, but the actual fuel could contain much lower ash, thus actually increasing the amount of fuel carbon relative to the whole. The approach of simple water iterations of the ""470 patent is useful in many situations, such as where the coal fuel bears little and constant ash, and, further, where very high accuracy and consistent effluent CO2 and H2O measurements are made, but has limitations in other applications.
Yet another approach was developed by the present inventor and was described in U.S. Pat. No. 5,790,420. The invention of the ""420 patent is noteworthy as it extends the approach of the ""470 patent to include combustion turbine systems. The ""420 patent is concerned with methods for improving thermal efficiency, determining effluent flows and determining fuel flow of fossil-fired systems through an understanding of the total energy flow (fuel flow rate x heating value), the As-Fired input to the system. The ""420 patent states that method errors will offset: xe2x80x9cthe sign of the error introduced by the heating value will always have an opposite change in the calculated fuel flowxe2x80x9d. Errors may be introduced in the ""420 patent by the use of its Equations 31 or 32 to compute the dry-base heating value, dependent on knowledge of the dry molar composition of the fuel. These dry compositions may be determined through xe2x80x9cuse of a correlation relating carbon, hydrogen, oxygen and sulfur contents to a dry-base heating value then correcting for waterxe2x80x9d. Fuel ash is suggested by the ""470 patent and the ""420 patent as being treated as a constant value. This is the case since the fuel constituents are solely defined per unity moles of dry-base fuel or as an As-Fired (for wet-base) fuel. A dry-base fuel contains ash; a wet-base fuel contains ash and water. If the effects of variable ash were to be addressed, fuel constituents would by necessity initiate from a base free of both ash and water, i.e., so-called xe2x80x9cMoisture-Ash-Freexe2x80x9d; such a base is not mentioned in either the ""470 patent or the ""420 patent. The ""420 patent explains that the molar quantity of fuel water xe2x80x9cis iterated until convergence is achievedxe2x80x9d, resulting in an As-Fired heating value. Again, as water is altered, the aggregate of all other fuel constituents are altered in opposite fashion to maintain a normalized unity moles of fuel. As with the approach of the ""470 patent, the ""420 patent requires high accuracy instrumentation, stating xe2x80x9cthe apparatus necessary for practicing the present invention includes utilization of any measurement device which may determine the effluent concentrations of H2O and CO2 to high accuracyxe2x80x9d. The approaches of the ""420 patent and the ""470 patent, which are rudimentary Input/Loss methods, are dependent on thermodynamically understanding a fossil-fired system without direct measurement of fuel or effluent flows, but there is room for improvement.
Another related art to the present invention involves using fuel water and fuel ash instruments intended for on-line operation. By fuel ash is meant the fuel""s non-combustible mineral content, before firing. These instruments employ a variety of techniques. Fuel water instruments include: capacitance techniques, microwave techniques, ultrasonics techniques and IR spectroscopy. Fuel ash instruments include: X-ray backscatter, X-ray fluorescence, gamma-ray backscatter, dual energy gamma-ray transmission, gamma-ray pair production, natural gamma radiation, prompt gamma neutron activation analysis, laser spectroscope, electron spin resonance and nuclear magnetic resonance. Knowing the fuel""s water and ash contents can lead to adjustment of the assumed heating value. This provided the fuel""s MAF chemistry remains constant. Further, these methods do not involve techniques in which errors made in the fuel ash measurement are off-set by fuel water concentrations. Further, common industrial accuracies are no better than xc2x15%, thus a xc2x15% error in fuel heating value. Further, whereas the direct determination of fuel water and ash would aid the present invention as overchecks of its calculated values, such instruments by themselves do not provide an integrated approach to the understanding of thermal systems. Clearly the computation of boiler efficiency, as integrally related to system parameters, is not made by simple use of these instruments.
Another related art to the present invention is Thermal Analysis which employs laboratory techniques of differential thermal analysis (DTA) and differential thermal gravimetrics (DTG), also termed thermogravimetry, combined with gas chromatography or other high accuracy gas analyzer, to determine the elementary analysis and proximate analysis of coal. This technique is intended for a laboratory environment, since it analyzes only gram amounts of coal. Obviously using tons of coal/hour by a thermal system such as a 100 Mwe power plant, developing a representative gram-size sample would present an insurmountable problem. One of the largest companies which supplies such equipment is Mettler Toledo, Hightstowns, N.J. which has been selling such equipment since at least 1980. This basic technique is mentioned in Chapter 9, xe2x80x9cMeasurement of Heat of Combustionxe2x80x9d contained in Steam, Its Generation and Use, cited above.
Another approach was developed by the American Society of Mechanical Engineers (ASME) and published as its Power or Performance Test Codes (PTC). Several of these codes discuss two methods which are relevant: the Input-Output Method invoked in PTC 4.1 (Steam Generators), 4.4 (Gas Turbine Heat Recovery Steam Generators), and PTC 22 (Gas Turbines); and the Heat-Loss Method invoked in PTC 4.1 and PTC 4.4. The Input-Output Method relies on the direct measurement of fuel flow. For coal-fired plants or any bulk-fuel systems, this has no applicability for the improvement of thermal efficiency for the above-discussed reasons of inaccuracy in fuel flow measurements. The Heat-Loss Method was intended to address the issue of inaccurate coal flow measurements by determination of unique stack and non-stack losses, thus: xcex7system=1.0xe2x88x92xcexa3(System Losses). The difficulty with this method, as in the case of the Output/Loss method, lies in the need to make two critical determinations: 1) either measurement of gaseous effluent flow directly or accurately knowing fuel chemistry leading to an effluent-to-fuel flow determination; and 2) when applied to coal-fired systems, measuring effluent ash flow and its associated unburned carbon in the ash. As discussed, the required accuracy is not possible on a consistent basis when measuring effluent flows. Further, the traditional use of the Heat-Loss Method requires an xe2x80x9caccurate, simple, and ultimate analysis of the fuel being fired.xe2x80x9d The difficulty in determining both xe2x80x9cbottomxe2x80x9d and xe2x80x9cflyxe2x80x9d ash flows, defined in PTC 4. 1, is evidenced by the fact the procedure is not preformed on any routine basis by any known coal-fired power plant.
In summary, the approaches of the Output/Loss Method, Munukutla and his colleagues, the ""470 patent, the ""420 patent, fuel water and fuel ash instrumentation, laboratory Thermal Analysis, the Input-Output Method, and the Meat-Loss Method all have significant limitations. The Output/Loss Method and both ASME Methods are flawed conceptually for at least typical large coal-fired systems. None of these methods are applicable for on-line monitoring. The methods of the ""470 patent and the ""420 patent do not consider: 1) the determination of fuel ash (intrinsically assuming a constant or known relationship between fuel carbon and fuel ash); and 2) the complexities of the non-water constituents, iterating simply on fuel water. That is, the methods of the ""470 patent and the ""420 patent simply alter fuel water under the assumption that the relationships between the fuel""s non-water constituents remain as constants or are predictable through correlations. If the determination of the fuel""s constituents is flawed, then the determination of the fuel""s heating value is flawed, and thus the fuel flow will be in error. Although as the ""470 patent and the ""420 patent state, such errors in heating value and fuel flow tend to off-set one another, this is typically true only if the ash is both a relatively small fraction of the total fuel and of essentially constant concentration. As will be seen in relation to the present invention, tolerating such errors voids useful information associated with absolute knowledge of heating value, voids the accurate determination of effluent flow, and voids any computational overcheck of the accuracies of the effluent measurements. None of these methods, except the ""470 Patent and the ""420 patent, consider multiple fuels which are commonly used in commercial power plants. None of these methods considers the thermodynamic determination of fuel ash. None of these methods considers the use of limestone injected into the combustion process. None of these methods, except the ""470 Patent and the ""420 patent, consider air pre-heater leakage such that gas concentrations on either side of the air pre-heater are useable in stoichiometric relationships. None of these methods, except the ""470 Patent and the ""420 patent, consider variable O2 in the combustion air local to the system.
Another approach was developed by the United States Environmental Protection Agency (EPA) as related to the determinations of effluent flow and individual emission rates (lbpollutant/million-Btufuel). EPA""s approach is described in its regulations, Chapter 40 of the Code of Federal Regulations (40 CFR). Specifics are described in 40 CFR Part 60, Appendix A, Methods 1, 2 and 17 defining various techniques for measuring effluent flows, and in 40 CFR Part 60, Appendix A, Method 19 defining xe2x80x9cF Factorsxe2x80x9d used to determine emission rates. The EPA requires the direct measurement of effluent flow from stationary sources of fossil combustion. The EPA also requires the reporting of emission rates for the major pollutants, determined using the F Factor technique. The EPA""s approach has the same shortcomings as discussed for the Output/Loss Method. The EPA approach does not require any inter-relationship between a computed fuel flow, which through stoichiometrics must be consistent with effluent flow. In a work by Lang, et al., reporting actual test results on a large power plant, EPA""s Methods 1, 2 and 17 resulted in effluent flows, on average, 12 percent higher than those consistent with system efficiency; this implies a 12% higher fuel flow, a large error in system understanding. Further, all EPA methods produced higher flows relative to those consistent with system efficiency, and none were consistent in themselves. These results are typical of the 12 to 15% bias reported throughout the industry. See F. D. Lang, et al, xe2x80x9cConfirmatory Testing of the Emissions Spectral Radiometer/Fuel Flow (ESR/FF) Instrumentxe2x80x9d, Electric Power Research Institute (EPRI) 1994 Heat Rate Improvement Conference, May 3-5, Baltimore, Md. In another study at two large power plants, use of EPA""s Method 2 produced 9.8 percent and 18.6 percent higher system heat rates (i.e., system efficiencies) based on measured effluent flows, see R. D. McRanie, et al, xe2x80x9cThe Electric Power Research Institute Continuous Emissions Monitoring Heat Rate Discrepancy Project, An Update Reportxe2x80x94December 1996xe2x80x9d, available from EPRI, Palo Alto, Calif. Studies by Lang and M. A. Bushey, analyzing 14 power plant test results, indicated that errors in emission rates using the EPA F Factor method could range from xe2x88x928 percent to +4 percent; and, when studying five dozen coal samples, they found that for 18 percent of the samples the error exceeded 5 percent. See F. D. Lang and M. A. Bushey, xe2x80x9cThe Role of Valid Emission Rate Methods in Enforcement of the Clean Air Actxe2x80x9d, EPRI 1994 Heat Rate Improvement Conference, May 3-5, Baltimore, Md.
Another related art to the present invention was developed by Roughton in 1980; see J. E. Roughton, xe2x80x9cA Proposed On-Line Efficiency Method for Pulverized-Coal-Fired Boilersxe2x80x9d, Journal of the Institute of Energy, Vol.20, March 1980, pages 20-24. His work served in part as the basis for the above cited EPA methods, and is related to the Output/Loss Method. Roughton""s method produces boiler efficiency (xcex7boiler) independent of fuel or effluent flows. His work computes boiler efficiency from the process"" stack and non-stack thermal losses, evaluated per unity of As-Fired fuel flow. Of these losses, the major loss is the stack loss. Whereas this is directly measured for the Output/Loss Method, Roughton relies on the statistical relationship between dry effluent flow and total As-Fired fuel energy flow assuming a water-free (dried) fuel. He relies on an observed ratio of these two quantities being essentially constant at 0.0008257 lbmeffluent/BtuAs-Fired Fuel (referred to below by the term Lfuel and called the xe2x80x9cfuel factorxe2x80x9d). The method""s accuracy is based solely on this value remaining constant. The EPA""s F-Factor approach fundamentally relies on this same ratio remaining constant, see the work by Lang and Bushey. It has been found that for a specific fuel, having a certain Rank from a certain geographical region, this ratio is indeed constant; but found not the same for different fuels. Further, it makes no claim as to predicting heating value; indeed Roughton states: xe2x80x9cUsing this ratio it is possible to obtain the dry stack loss and moisture loss without the need for an ultimate analysis of the coal or for an accurate determination of calorific valuexe2x80x9d of the As-Fired fuel.
Complete thermodynamic understanding of fossil-fired systems, for the purposes of improving system efficiency and regulatory reporting, requires the determination of fuel mass flow rate, fuel chemistry, fuel heating value, total effluent flow rate, emission rates of the common pollutants, and thermal efficiency of the overall combustion process. All such quantities must be determined with thermodynamic consistency. There is a need for an improved approach to these determinations.
The approach of the present invention, termed the Input/Loss Method, consistently determines fuel flows, effluent flows, emission rates, fuel chemistry, fuel heating value and thermal efficiency, resulting in improved determinations of the thermal efficiency of any fossil fueled system. The Input/Loss Method has been applied through computer software, installable on a personal computer, and demonstrated being fully operational. This computer and software is termed a Calculational Engine, receiving data from a fossil fueled system""s data acquisition devices. The Calculational Engine operates continuously, i.e., in xe2x80x9creal timexe2x80x9d or xe2x80x9con-linexe2x80x9d, as long as the fossil fueled system is receiving and burning fuel.
Prior to on-line operation, the Input/Loss Method requires certain initializing data involving reference fuel chemistry and heating value, and reference fuel stoichiometric data associated with the reference fuel chemistry. In addition, those computer programs which will describe the steam generator""s air handling equipment and its heat exchangers, or the gas turbine and its heat exchangers and/or the steam turbine cycle, require routine initiating input. If operating for the first time, initial estimates of fuel chemistry and heating value are required, typically the reference values are used. Effluent measurements are required. If off-line, the assumed effluent measurements may be either consistent with the assumed fuel, or take a bias for the study of instrumentation error. Using these data, error analyses are preformed indicating which assumptions will yield minimum errors by exercising the Input/Loss Method as an analytical tool. Two such assumptions are required. The first of these is how the molar fraction of fuel ash, using a Moisture-Ash-Free (MAF) base, xcex1MAF-Ash, should be treated: using a constant value of xcex1MAF-Ash; or correlating xcex1MAF-Ash as a function of MAF heating value, HHVMAF; measuring it directly using a fuel ash meter; or, preferably, determining xcex1MAF-Ash by explicit solution requiring the measurement of the system""s wet combustion Air/Fuel mass ratio (a relative measurement routinely made in all fossil fueled systems). In general, this Air/Fuel ratio requires normalization given measurement bias such that stoichiometric consistency is achieved. An alternative to the Air/Fuel ratio is the indicated fuel mass flow rate, also routinely measured in all fossil fueled systems, but requiring normalization (using error analysis procedures of this invention). The second assumption is how the molar fraction of fuel water, using a MAF base, xcex1MAF-water, should be influenced by effluent water: using a constant value of the effluent H2O, is preferred; or the effluent stream may be instrumented for the direct measurement of H2O.
When operating in real time and using the initialized data, the Input/Loss Method performs the following sequential steps: 1) obtain measurements of the concentrations of the common pollutants to accuracies common to the electric power industry; 2) obtain measurements of the gross shaft electrical power, mechanical power, and/or the useful energy flow developed from the system; 3) if multiple fossil fuels are used, their properties are combined (e.g., using the FUEL.EXE program) to form a composite fuel, composite higher heating value, and, even if a single fuel, to prepare input for step 4; 4) fuel concentrations and heating value are input to a steam generator or gas turbine computer simulator (e.g., the EX-FOSS.EXE program); 5) obtain measurements of the effluents O2 , CO2, SO2, and H2O if appropriate, and the indicated Air/Fuel ratio (or indicated fuel mass flow) if appropriate, to accuracies common to the electric power industry; 6) the steam generator, or gas turbine, computer simulator is executed producing consistent stoichiometrics given the supplied fuel and input of the measured effluent O2 and common pollutants, including the computed effluents CO2, SO2 and H2O values, the Air/Fuel ratio, the moles of fuel per 100 moles of dry gaseous effluent (termed x), and at least the following thermal performance parameters: fuel and effluent flows, system thermal efficiencies and emission rates xe2x80x94all consistent with the input fuel""s chemistry and heating value; 7) by solution the molar MAF fractions of fuel carbon, water and sulfur are computed as explicit stoichiometric solutions, both dependent principally on the effluents O2, CO2, SO2 and H2O (which was not done in the ""470 patent or the ""420 patent); 8) through dependency on the molar MAF fraction of fuel carbon, the molar MAF fractions of fuel nitrogen, oxygen and hydrogen are determined; 9) as optioned in the initialization, the molar MAF fraction of fuel ash is determined, the preference is by explicit solution; 10) the molar MAF fuel species are converted to a molar dry base, then converted to a molar wet base (As-Fired), and finally to wet weight fractions (As-Fired); 11) the higher heating value is computed based on changes to the fuel""s MAF constituents, then converted to a dry base, and then to an As-Fired base; 12) the results of the last two steps, fuel chemistry and heating value, are then input to the FUEL.EXE program (or a similar program) of step 3 and the processes repeated until convergences on the fuel moles (x), As-Fired heating value (HHVAF), fuel flow and minor stoichiometric terms are achieved; 13) after convergences are achieved, and if errors are within criteria, the procedure is deemed successful, if not instrumentation is identified by the process allowing for both correction and the minimization of errors through application of multidimensional optimization techniques; and finally, 14) after convergences are achieved and error analysis completed, the operation of the system is adjusted to improve its thermal efficiency and/or to minimize the polluting emissions and/or to report effluent flow and emission rates to regulatory authorities. When this process is completed all objectives of this invention will have been met.
The fossil fueled system operator has assurance of complete thermodynamic understanding of the system because of: 1) explicit relationships between measured effluents and the key fuel constituents of carbon, water and ash; 2) an explicit relationship between these and the computed heating value; 3) an explicit relationship between the fuel energy flow (heating value and flow) and the useful energy flow developed from the combustion gases; and 4) an explicit relationship between fuel flow and effluent flow.
The apparatus necessary for practicing the present invention includes any measurement device (or combination of devices) which determines the effluent concentrations of O2 and CO2, and, if appropriate, effluent H2O, CO and SO2 to current standards found in the electric power industry. Further, the system""s routinely measured Air/Fuel ratio (or fuel mass flow) is required provided it is consistent, not necessarily accurate (normalization of the signal is provided) if fuel ash is to be determined in real time. Further, routine and common thermal system data, all of which are typically known to thermal system operators, is required such as: effluent gaseous temperature; combustion air psychrometrics; working fluid flows, pressures and temperatures at key heat exchangers, and the like.
It is therefore an important object of the present invention to provide a procedure for determining the energy flow of the input fuel to a fossil fueled system without direct measurement of the fuel flow rate or heating value or fuel chemistry, and in accomplishing this, to assure that system efficiency, and system mass and energy in-flows and out-flows are consistent.
It is a further object of the present invention to provide a quantitative procedure of demonstrating the consistency of the Method""s results.
It is a further object of the present invention to provide a means for determining the energy flow of the input fuel of a fossil fueled system by predicting the composition of the input fuel, including its ash content, and with this information predict heating value, and then back-calculate the input fuel flow rate from a classical use of system efficiency.
It is a further object of the present invention to provide a means for determining both the total effluent flow rate (cubic feet/hour or pounds/hour), the emission rates (pounds/million-Btufuel) and flow rates (pounds/hour) of all effluents including the common pollutants produced from a fossil fueled system by determining the fuel flow rate indirectly and having knowledge of the fuel""s chemistry and effluent concentrations.
It is a further object of the present invention to provide a procedure for determining the thermal efficiency of a fossil fueled system without directly measuring the input fuel flow rate.
It is a further object of the present invention to provide an intrinsic self-checking procedure of the Method of this invention, computed in real time, in-process, in which the computed and measured effluent CO2, effluent H2O, Air/Fuel ratio and computed fuel factor are compared for consistency, and if errors are within criteria the procedure was deemed successful, or not.
It is a further object of the present invention to provide a procedure to identify which of the effluent CO2, effluent H2O and Air/Fuel ratio measurements is producing erroneous measurements, such that corrective actions may be taken if appropriate.
It is a further object of the present invention to provide a procedure in which the errors made in predicting the concentration of fuel water will be off-set by fuel ash, though an explicit computation of fuel ash. Thus any error in fuel water, as off-set by fuel ash, will have negligible effect on the As-Fired heating value.
It is a further object of the present invention to provide a means for determining the flow of a fuel""s solid non-combustible mineral material (commonly referred to as fuel ash) associated with coal fuel, and thus adjust and improve the operations of the ash removal equipment in a combustion system""s effluent stream.
It is a further object of the present invention to demonstrate that all aforementioned objectives associated with a fossil fueled system are also, and herein declared, objectives associated with any fossil fueled system producing electrical power, mechanical power and/or useful energy flow from the system.
It is a further object to provide an approach which yields improved results as compared with EPA Methods 1, 2, 17, and/or 19.
It is a further object to provide an approach which yields improved results as compared with the methods of the ASME Power Test Codes 4.1, 4.4, and/or 22.
Other objects and advantages of the present invention will become apparent when the Method and apparatus of the present invention are considered in conjunction with the accompanying drawings.